Vibration detection in a drill string based on multi-positioned sensors

ABSTRACT

In some example embodiments, a system includes a drill string having a drill bit. The drill string extends through at least part of a well bore. The system also includes a first vibrational sensor, positioned on the drill bit to measure, at a first location on the drill string, an amplitude of one or more of an axial vibration and a lateral vibration. The system also includes a second vibrational sensor, positioned above the drill bit and on the drill string. The second vibration sensor is to measure, at a second location on the drill string, one or more of an axial vibration and a lateral vibration. The system includes a processor unit to determine a type of vibration based on a comparison of the amplitude at the first location to the amplitude at the second location, wherein the type of vibration is at least one of bit whirl of the drill bit and a while of a bottom hole assembly that is part of the drill string.

RELATED APPLICATIONS

This application is a U.S. National Stage Filing under 35 U.S.C. 371from International Application No. PCT/US2010/036409, filed May 27,2010, and published as WO 2010/138718 A1 on Dec. 2, 2010, which claimspriority under 35 U.S.C. 119(e) to U.S. Provisional Patent ApplicationSer. No. 61/181,385, filed May 27, 2009; which applications andpublication are incorporated herein by reference in their entirety.

TECHNICAL FIELD

The application relates generally to hydrocarbon recovery operations. Inparticular, the application relates to a configuration for vibrationdetection in a drill string using multi-positioned sensors along thedrill string.

BACKGROUND

During drilling operations, vibrations within a drill string can berelated to a number of drilling problems. If there are large vibrations,one or more components in the drill string, the drill bit, drill collar,etc. may be prematurely worn or broken. Moreover, the drillingperformance can be decreased. The types of vibrations on a drill stringcan include longitudinal or axial vibration, torsional vibration, andlateral vibration. While these vibrational modes (including combinationsof the vibration types) can be destructive downhole, or can beindicative of conditions that would be desirable to be known by thoseconducting the drilling operations, they can be very difficult todetermine at the surface. Additionally, in order to facilitatecorrective action, determining the operational mode of the drill stringin as close to real time as possible would be helpful in avoiding thepossible detrimental results.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the invention may be best understood by referring to thefollowing description and accompanying drawings which illustrate suchembodiments. The numbering scheme for the Figures included herein aresuch that the leading number for a given reference number in a Figure isassociated with the number of the Figure. For example, a tool 100 can belocated in FIG. 1. However, reference numbers are the same for thoseelements that are the same across different Figures. In the drawings:

FIG. 1 illustrates a drilling well during Measurement While Drilling(MWD) operations that includes a drill string having multi-locatedsensors for detecting vibrations, according to some example embodiments.

FIG. 2 illustrates part of a drill string having multi-located sensorsalong the drill string for vibration detection along the drill string,according to some example embodiments.

FIG. 3 illustrates part of a drill string having multi-located sensorsalong the drill string for vibration detection along the drill string,according to some other example embodiments.

FIG. 4 illustrates a flow diagram for operations for detection of avibration mechanism in a drill string, according to some exampleembodiments.

FIG. 5 illustrates a graph of the angular change of the tool, accordingto example embodiments.

FIG. 6 is a plot of an angular measurement when the signal levels arevery low, according to some embodiments.

FIG. 7A-B shows the characteristics of the down sampling filter,according to some example embodiments.

FIG. 8 illustrates the graph of the total angle calculated for a 20second data window, according to some example embodiments.

FIG. 9 illustrates a graph of the angular speed per unit of time derivedfrom FIG. 8, according to some example embodiments.

FIG. 10 illustrates a distribution of frequencies, according to someexample embodiments.

DETAILED DESCRIPTION

Methods, apparatus and systems for vibration detection in a drill stringusing multi-positioned sensors, sensors at spaced locations, along thedrill string are described. In the following description, numerousspecific details are set forth. However, it is understood thatembodiments of the invention may be practiced without these specificdetails. In other instances, well-known circuits, structures andtechniques have not been shown in detail in order not to obscure theunderstanding of this description.

System Operating Environment

An example system operating environment for a vibration analysis systemis described. FIG. 1 illustrates a well during Measurement WhileDrilling (MWD) operations; wherein the well 106 includes a drill string108 having multiple sensors for detecting vibrations, according to someexample embodiments described herein. It can be seen that surface system164 includes a portion of a drilling rig 102 located at the surface 104of the well 106. The drilling rig 102 provides support for the drillstring 108. The drill string 108 can operate to penetrate a rotary table110 used to rotate the drill string and to thus drill a borehole 112through subsurface formations 114. The drill string 108 will ofteninclude a Kelly 116, drill pipe 118, and a bottom hole assembly 120coupled at the lower portion of the drill pipe 118.

In some example embodiments, the bottom hole assembly 120 includes oneor more drill collars 122, a downhole logging tool 124, and a drill bit126. The drill bit 126 can operate to create a borehole 112 bypenetrating the surface 104 and subsurface formations 114. The downholetool 124 can comprise any of a number of different types of toolsincluding MWD (measurement while drilling) tools, LWD tools, and others.In some example embodiments, the logging tool 124 will containprocessing capability and circuitry for receiving measurements from thedescribed sensors, and evaluating the measurements downhole. Where suchdownhole processing is performed, the results may be communicated to thesurface through conventional data transmission systems known in the art,and the measurement data and the analysis thereof will, in someexamples, also be retained in memory in the tool for later review, ifneeded. As further described below, in some example embodiments,different types of vibrational sensors are positioned at differentlocations along the drill string to determine a type of vibrationmechanism (e.g., axial, torsional, lateral, etc.) and the location ofthe vibration (e.g., drill bit, bottom hole assembly, etc.).

As noted above, during drilling operations the drill string 108(typically including the Kelly 116, the drill pipe 118, and the bottomhole assembly 120) can be rotated by the rotary table 110. In additionto, or alternatively, the bottom hole assembly 120, or some portionthereof, can also be rotated by a motor (e.g., a mud motor) that islocated downhole. The drill collars 122 can be used to add weight to thedrill bit 126. The drill collars 122 can also operate to stiffen thebottom hole assembly 120, allowing the bottom hole assembly 120 totransfer the added weight to the drill bit 126, and in turn, to assistthe drill bit 126 in penetrating the surface 104 and subsurfaceformations 114.

During drilling operations, a mud pump 132 can pump drilling fluid(sometimes known by those of skill in the art as “drilling mud”) from amud pit 134 through a hose 136 into the drill pipe 118 and down to thedrill bit 126. The drilling fluid flows out from the drill bit 126 andis returned to the surface 104 through an annular area 140 between thedrill pipe 118 and the sides of the borehole 112. The drilling fluid isthen be returned to the mud pit 134, where such fluid is filtered.Typically, the drilling fluid is used to cool the drill bit 126, as wellas to provide lubrication for the drill bit 126 during drillingoperations. Additionally, the circulation of the drilling fluid is usedto remove subsurface formation 114 cuttings created by operating thedrill bit 126.

Configurations for Positioning of Sensors Along a Drill String

FIG. 2 illustrates part of a drill string having multi-located sensorsalong the drill string for vibration detection along the drill string,according to some example embodiments. In particular, FIG. 2 illustratesparts of the drill string 108. The drill string 108 includes the drillpipe 118 that is coupled to the bottom hole assembly 120. The drill bit126 is coupled in bottom hole assembly 120 through a threadedconnection. A first vibrational sensor 202 is positioned at (in) or nearthe drill bit 126. In some embodiments, more than one vibrational sensor202 may be positioned at or near the drill bit 126. A second vibrationalsensor 204 is then positioned at another location in the drill string,such as, in this example embodiment, toward the top of the bottom holeassembly 120. In some embodiments, more than one vibrational sensor 204may be positioned at or near the bottom hole assembly 120. In someembodiments, the vibrational sensor 202 and the vibrational sensor 204can be different types of transducers. Additionally, in some cases itmay be desired to place additional sensors in the drill string, forexample, in or near components of interest, such as a mud motor, whenpresent in the drill string. In many embodiments, the vibrationalsensors 202 and 204 will each be multi-axial sensors, preferablytri-axial accelerometers. As noted above, the downhole logging tool 124in the bottom hole assembly 120 can include a processor unit, which inthis example, will be used to process signals from the vibrationalsensors downhole, thereby facilitating evaluation of downhole conditionsessentially in real time (allowing time primarily for communication ofmeasurement signals from the sensors to the processor unit, (implementedin part in either hardware or software), and the evaluation of thosesignals). As will be apparent from the discussion herein, by comparingthe measured vibrations on (or near) the drill bit, with the monitoredvibrations further up the drill string (such as near the top of the BHA,in this example), one can evaluate the operational conditions of thedrill string.

As further described below, in some embodiments, the vibrational sensor202 and the vibrational sensor 204 each measure or monitor amplitudes ofone or more of lateral vibration, longitudinal vibration, and torsionalvibration. The vibrational sensor 202 and the vibrational sensor 204 caneach be representative of one or more different types of measurementdevices. For example, in some example embodiments, the vibrationalsensor 202 and the vibrational sensor 204 will each include one or moreaccelerometers; and as the accelerometers will preferably be oriented tomeasure lateral motion (e.g., X and Y directions transverse to the axisof the drill string) and longitudinal vibration (e.g., Z direction alongthe axis of the drill string), the accelerometers will preferably betri-axial accelerometers. Alternatively or in addition, either (or both)of vibrational sensors 202 and 204 can also include a magnetometer or aHall effect device to determine rotations of the drill bit or drillstring. Such devices can be used to determine torsional vibration, aswell as many other operating conditions, as set forth below.

Example Borehole Conditions

For purposes of illustration of the concepts herein, relative terms of“low,” “medium” and “high” acceleration measurements are used herein.Such terms are not intended to reflect any specific values, as thequantitative measurements will be recognized to those skilled in the artto be variable depending on the drill string utilized and the componentstherein (for example, the sensors used, and the systems used in thedrill string to mitigate transfer of shock and vibration through thedrill string). For example, in terms of actual forces experienced, inmany operational situations, with smooth drilling, the axialacceleration on the drill string is generally on the order of 0.1 g; butit can exceed 100 g for short time intervals (for example, a fewmilliseconds) in rough drilling conditions; and the lateral shock canexceed 1,000 g in rough drilling conditions. Hence, in absolute forces,low vibration might be characterized, for example, by a mean vibrationaxial vibration level less than about 0.1 g with peaks on the order of 1g for a few ms, and cross-axial vibration less than about 1 g with peaksno larger than 10 g. Similarly, high vibration might be characterized,for example, as a vibration in which either the axial vibration exceeds1 g on average, it has peak accelerations exceeding 100 g, (for example,for 1 or more times per second), or the lateral vibration exceeds 10 gon average or the lateral vibration has peaks exceeding a few hundred gone or more times per second. Medium level vibration could then, in thisexample, be characterized by anything between those two states. Forclarity, however, the above examples are only examples, and arerepresentative only of absolute forces; and thus actual measuredvibration forces in any tool string may be substantially different fromthe example values, depending on the measurement system and the drillstring characteristics, as discussed above.

As noted above, the measured axial, torsional, and/or lateral vibrationscan determine different conditions downhole relative to the drill stringoperation. For example, an axial motion of a given magnitude can beindicative of bit bounce of the drill bit. Large weight on bitfluctuations can cause the drill bit to repeatedly lift-off and thenimpact the formation. For bit bounce, the indicative responses of thevibrational sensors 202 and 204 include high peak acceleration in the Zdirection from both sensors. When comparison of the vibrational sensormeasurements from both sensors indicates high peak acceleration alongthe Z axis, and thus indicates a bit bounce operational mode, thedriller may than use that determination to change one or more drillingparameters (such a weight on bit, speed of rotation, etc.) to correctthe undesired operational mode.

Another downhole condition of concern is “stick slip.” Stick slip is anon-uniform drill bit rotation in which the drill bit stops rotatingmomentarily at regular intervals causing the drill sting to periodicallytorque up and then spin free. When stick slip occurs, the average RPMsignal may be generally uniform, but the instantaneous RPM signal mayrange from nearly 0 RPM to several multiples of the average RPM signal.A torsional motion of a given magnitude can be indicative of stick slip;and thus can be identified by comparison of the accelerationmeasurements from the spaced sensors. As a result of the motioncharacteristics during conditions of stick slip, indicative measurementsof the vibrational sensors can include low to medium peak X and Yaccelerations. For example, the above-described changes in instantaneousRPM will often reflected in an “extremely small” measured accelerationfor some significant period of time (such as over the time period of afew revolutions), followed by a significantly increased measuredacceleration as the string breaks free. The relative values of theseacceleration measurements can be established relative to any desiredreference, for example, the standard deviation typical of a drillingoperation, as represented (by way of example only): by stand-alonecalibrations of the sensors; by empirical or historical reference data(which in some cases may be tailored to specific drill stringconfigurations or types of configurations); or by calibrationmeasurements taken with the drill string in question, as just threeexamples. As another example, the measured acceleration measurements maybe compared to reference measurements from vibrational sensors in thedrill string at a location where sticking would not be expected, such asthe portion of the well above the bottom hole assembly. When thesevalues are evaluated relative to such reference values (such as observedoutputs of the same or comparable X- and Y-sensors under known normaldrilling conditions), then comparison to the known reference can beaccording to any desired relation to the reference values. On desirablesuch relation is to the standard deviation of the referencemeasurement(s). For example, in an example comparison, “extremely small”might mean less than some fraction of the standard deviation of thereference (e.g., for example 0.25 standard deviations). Typically inevaluating stick slip, the condition of an “extremely small” measuredacceleration measurement must prevail for a significant portion of theexpected rotational period (as e.g., at least 0.25 of a rotationalperiod). The above-referenced observation of “low to medium peak X and Yaccelerations” results from the fact that when the bit breaks free,normal drilling takes place, and the heavy side slap observed in some ofthe other types of motion, such as in chaotic whirl, will not typicallybe observed with stick-slip. Additionally, the acceleration measurementsfrom the spaced sensors will be compared to one another, and in caseswhere the sensors are sufficiently spaced as to not be uniformlyimpacted by the sticking forces, the acceleration measurements willoften be of different frequency and phase. Again, and as with theundesired operational modes as described below, comparison of the sensorsignals to each other, and preferably also to a reference, allowsidentification of the system operational mode in essentially real time,and facilitates the driller taking corrective action. In the case of awhirl condition, that corrective action will often include reducing thesurface RPM of the drill string.

Another downhole condition of interest is drill bit whirl. Drill bitwhirl includes an eccentric rotation of the bit about a point other thanits geometric center, typically caused by the bit or by wellboregearing. Bit whirl induces high frequency lateral vibration of the bitand the drill string. Without the use of analytical techniques asdescribed herein, bit whirl can be very difficult to detect at thesurface by the drilling operators. Bit whirl can cause many forms ofdeleterious conditions, including bit cutter impact damage, over-gaugeforming of the borehole, bottom hole assembly connection failures, andMWD component failures. For bit whirl, the indicative responses of thevibrational sensors can include high peak X and Y accelerations, whilethe average X and average Y accelerations are about equal. High peak Xand Y accelerations may be indicative of bit whirl because the motiontends to cause the bit to slam against the borehole wall. The averageacceleration, however, may not appear to be too high as the peak valuesare from impulsive events. No asymmetry is expected in the X- andY-values over a period of a few seconds, and thus average X and averageY acceleration measurements that are about equal signifies that, otherthan the impulsive events, the performance appears to be normal drillingoperations. Where one or both of the vibrational sensors 202, 204includes a magnetometer or other rotationally sensitive device, chaoticdrill bit whirl will be characterized by frequencies significantly abovethe measured rotational frequency. Additionally, the onset of suchchaotic drill but whirl can be observed by the frequencies of theacceleration measurements tending to increase in a sequence of doubling,tripling, and doubling or tripling again, and ultimately reaching chaos.Comparison of the measurements from the two sensors further assists inevaluating the location of the whirl and thus the actual operationalmode, for example, distinguishing between drill bit whirl and BHA whirl,as discussed below.

Another downhole condition of interest is Bottom Hole Assembly (BHA)whirl. BHA whirl typically includes the BHA gearing around the boreholeand results in several lateral shocks between the bottom hole assemblyand the well bore. BHA whirl can be a major cause of many drill stringand MWD component failures. BHA whirl can occur while rotating/reamingoff-bottom and can also be very difficult to detect at the surface.Bottom hole assembly whirl can cause different MWD component failures(e.g., motor, MWD tool, etc.), localized tool joint and/or stabilizerwear, washouts or twist-offs due to connection fatigue cracks, increasedaverage torque, etc.

Lateral shocks can also occur during the drilling operation. Lateralshocks can be caused the bottom hole assembly moving sideways, or insome cases whirling forward and backwards randomly. Lateral shocks ofthe bottom hole assembly (BHA) can be induced either from drill bitwhirl or from rotating an unbalanced drill string. Similar to whirl,without the use of example techniques as described herein, lateralshocks can be very difficult to detect at the surface. Suchnon-steady-state motion may often be recognized from data indicatingmedium or high peak lateral accelerations but low average accelerationsof the vibration. Lateral shocks have also been linked to different MWDand downhole tool connection failures. Lateral shocks can causedifferent MWD component failures (e.g., motor, MWD tool, etc.),localized tool joint and/or stabilizer wear, washouts or twist-offs dueto connection fatigue cracks, increased average torque, etc. For lateralshocks, the responses of the vibrational sensors can include medium tohigh peak X or Y accelerations. In some example embodiments, peak X andY are about equal. In some situations, there are no dominant peaks inthe frequency plots of the burst data. Lateral shock can be largelydefined by medium to high peak accelerations on either axis. Oneindication of many forms of drill string resonant condition is repeatedshocks in a given direction. The direction may not correspond to an X-or Y-axis acceleration, but rather the peak X- and Y-accelerations occursimultaneously or in very close time proximity to one another (such as,on the order of milliseconds) and have some generally fixed ratio, orremain within a fixed bound, with respect to each other. While the ratiorelationship of the acceleration measurements may be defined by personsof skill in the art having the benefit of the present disclosure, onepossible example definition as follows: for a time interval of about 10seconds,((avg._of_max_(—) Y*std._deviation_of X)+(avg._of_max_(—) X*std.deviation_of_(—) Y))/((avg._of_max_(—) X)^2+(avg._of_max_(—) Y)^2)  Eq.1

In some operations, there is a vibration modal coupling involving allthree motions (axial, torsional, and lateral vibrations). Such couplingcan create axial and torque oscillations and high lateral shocks of theBHA. Vibration modal coupling can cause various of thepreviously-described operational problems, including different MWDcomponent failures (e.g., motor, MWD tool, etc.), bit cutter impactdamage, collar and stabilizer wear, washouts or twist-offs due toconnection fatigue cracks, etc. For vibration modal coupling, as withindicia of lateral shock, the representative responses of thevibrational sensors can include high peak X, Y and Z accelerations,accompanied by low to medium average X and Y accelerations. In manycases of such modal vibration coupling, the above indicia will beaccompanied by discernible frequency patterns in the measurements.

In some example embodiments, a processor unit within the downhole tooland/or at the surface receives the vibration measurements from thevibration sensors 202 and 204. The processor unit is configured todetermine a type of vibrational mode, and thus a drill string condition,based on a comparison of the measurement at the first location to themeasurement at the second location, and in many cases in furtherreference to a reference value, as discussed above. An amplitude-basedevaluation will be adequate for some evaluations, and thus in someexample embodiments, the frequency response is not required for theevaluation. For example, large amplitude vibrations are dangerous,whether they are random or have some well-defined frequency content. Andthus the techniques described herein may be of substantial value inidentifying some operational modes without substantial consideration ofthe frequency content of the measurements. However, for some operationalmodes, such as drill string resonance and bit whirl, betteridentification of the operational mode can be obtained through use of acombination of amplitude and frequency. That identification of theoperational mode (i.e., the cause of the vibration), makes it possiblefor the driller to take appropriate actions to remove the cause, so asto return to “normal” drilling operation modes.

FIG. 3 illustrates part of a drill string having multiple sensors alongthe drill string for vibration detection along the drill string,according to some other example embodiments. In particular, FIG. 3illustrates parts of the drill string 108, including the drill pipe 118that is coupled to the bottom hole assembly 120. The bottom holeassembly 120 is coupled to a drill bit 126 through a threadedconnection. A vibrational sensor 202 is positioned at or near the drillbit 126. In some embodiments, more than one vibrational sensor 202 maybe positioned at or near the drill bit 126. A vibrational sensor 204 ispositioned at or near the bottom hole assembly 120. In some embodiments,more than one vibrational sensor 204 may be positioned at or near thebottom hole assembly 120. Additionally, a vibrational sensor 312 may bepositioned on the drill string at or near the surface. In someembodiments, the vibrational sensor 202, the vibrational sensor 204 andthe vibrational sensor 312 can be different types of transducers.Although, as noted above, the vibrational sensors 202, 204 and 312 caneach desirably be a tri-axial accelerometer. The logging tool in thebottom hole assembly 120 can include a processor unit.

Example embodiments are not limited to the configurations illustrated inFIGS. 2-3. In another example, the drill string could include avibrational sensor at the bottom hole assembly and a vibrational sensorat or near the surface. In another example, the drill string couldinclude a vibrational sensor at or near the drill bit and at or near thesurface. In another example, additional sensors can be positioned atother locations along the drill string (e.g., between the BHA and thedrill bit, between the BHA and the surface, etc.).

Example embodiments include a detection of vibration through use ofmultiple vibration sensors placed in and along the drill string.Vibrational sensors to sense lateral vibration may be placed near thedrill bit and away from the drill bit. By comparing the lateralvibration near the drill bit to the lateral vibration data away from thedrill bit, embodiments as described herein may be used to detect avibrational mode in the drill string, and to evaluate that vibrationalmode to, as just one example, differentiate drill bit whirl from BHAwhirl. The multiple sensors may also be useful to obtain vibration dataat critical components along the drill string, and thus to evaluateconditions, such a potential failure conditions, for such components.

Operations for Detection of Vibration Mechanisms

This section describes operations performed in accordance with someembodiments of the invention. In certain embodiments, the operations areperformed by using one or more processors in the processor unit toexecute instructions residing on machine-readable media (e.g.,software); while in other embodiments, the methods are performed byhardware or other logic (e.g., digital logic). The system operations aredescribed relative performing such operations downhole. However, in someembodiments, some or all of these operations may be performed at thesurface.

FIG. 4 illustrates a flow diagram for operations for detection of avibration mechanism in a drill string, according to some exampleembodiments. FIG. 4 illustrates operations that may be executed by theprocessor unit in the downhole tool and/or at the surface.

At block 402, an amplitude measurement of at least one of an axialvibration, a torsional vibration and a lateral vibration (andpreferably, for many systems, all 3 measurements) is received from afirst vibrational transducer positioned at or near the drill bit, whichis at a first location on the drill string. The processor unit receivesthe amplitude measurement from the vibrational sensor 202. Thus, thevibrational sensor 202 can measure an amplitude for one, some or all ofan axial vibration, a torsional vibration and a lateral vibration. Forexample, the vibrational sensor 202 is preferably a tri-axialvibrational sensor 202 (such as an accelerometer) that measures lateral,axial, and torsional vibration. The first vibrational sensor 202transmits the amplitude measurements to the processor unit using any ofa number of different types of communications. For example, the firstvibrational sensor 202 can be wired or otherwise operably coupled tocommunicate measurement signals to the processor unit or to components(buffers, etc.) associated therewith. Such other communication may bebased on electromagnetic wireless communication, fiber opticcommunication, mud pulse communication, etc. The flow continues at block404.

At block 404, an amplitude measurement of at least one of an axialvibration, a torsional vibration and a lateral vibration is receivedfrom a second vibrational transducer positioned above the drill bit,which is at a second location on the drill string. The processor unit206 receives the amplitude measurement from the vibrational sensor 204.Thus, the vibrational sensor 204 can be at or near the bottom holeassembly. In some embodiments, this second vibrational sensor can becloser or further away from the drill bit. In some embodiments, thissecond vibrational sensor can be at or near the surface. In someembodiments, the distance from the first vibrational sensor and thesecond vibrational sensor is at least a distance X, where the distance Xcan be between 100-200 feet, between 50-100 feet, between 10-200 feet,etc. The flow continues at block 406.

At block 406, the amplitude measurement from the first location iscompared to the amplitude measurement from the second location on thedrill string. In many examples, the measurement signals will be ofacceleration, and at least a portion of the comparison will be based onthe frequency characteristics of the signals from the spaced locations.The processor unit 206 performs this operation. The flow continues atblock 408.

At block 408, a vibration mechanism on the drill string is detectedbased on the comparison of the vibrations at the two different locationson the drill string. The processor unit can detect the vibrationmechanism. In some example embodiments, the detection is based on theseverity of the vibrations. In some example embodiments, the processorunit can analyze the acceleration of the vibrations in the X, Y and Zdirections. In some cases, the processor unit can evaluate thevibrational measurements relative to some reference, either in terms ofreference measurement values or thresholds, or by grouping(categorizing) the acceleration measurements (both average and peakacceleration of the vibrations) into low, medium and high bands(appropriate for the drill string configuration, as described earlierherein), for analysis.

For purposes of illustration, and not of limitation, in some exampleembodiments, example ranges for evaluating sensor vibrationalmeasurements might be: for average acceleration for X or Y axes, a lowrange of 0-3 g, a medium range of 3-6 g and a high range of greater than6 g; and for average acceleration for the Z axis, a low range of 0-2 g,a medium range of 2-4 g and a high range of greater than 4 g.Alternatively, in other example systems, different ranges might be used,for example, for average acceleration for X-Y axes, a low range of 0-1g, a medium range of 1-2 g and a high range of greater than 2 g, withcorresponding adjustments to measurements on the Z axis. In such exampleembodiments, ranges for peak acceleration measurements could beattributed as follows: for the X and Y axes, a low range of 0-30 g, amedium range of 30-90 g and a high range of greater than 90 g; and forthe Z axis, a low range of 0-15 g, a medium range of 15-40 g and a highrange of greater than 40 g.

Other Configurations

This section describes other configurations and operations performed inaccordance with some embodiments. In certain embodiments, the operationsare performed by a processor executing instructions residing onmachine-readable media (e.g., software), while in other embodiments, themethods are performed by hardware or other logic (e.g., digital logic).The system operations are described relative performing such operationsdownhole. However, in some embodiments, some or all of these operationsmay be performed at the surface.

Some example embodiments include a method for a real time frequencyanalysis of the vibration modes in the drill string to detect drill bitwhirl and torsional resonance. In some example embodiments, vibrationfrequency and magnitude information are first obtained downhole by FastFourier Transform (FFT) and relayed to the surface. Embodiments maydifferentiate among bit whirl vibration, Bottom Hole Assembly (BHA)vibration and lateral shock vibration.

For bit whirl vibration, the vibration frequency is equal to the numberblades and cones on the bit, multiplied by the downhole Rotations PerMinute (RPMs) of the drill string. Thus, if the vibration frequency is amultiple of the downhole RPM frequency, the vibration is most likely dueto bit whirl. If the vibration frequency is not such a multiple, suchvibration is most likely a bottom hole assembly (BHA) vibration. Ifthere are multiple frequencies with similar magnitude rather than onedominant frequency mode, the vibration is most likely due to lateralshocks from sources such as the motor or stabilizer.

Some example embodiments include a method for detecting stick slip usingtime-domain and/or frequency domain analyses from downhole measurements.In some example embodiments, this analysis involves measuring thevariation in RPM, such as may be determined using the angular positionof the downhole tool. The angular position and the RPM can be determinedusing a downhole sensor (such as a magnetometer) which provides anangular indication relative to magnetic north. In some exampleembodiments, stick-slip can be detected from the magnitude and frequencyspectrum of the RPM measurement. In a variation of the embodiment, thestick slip frequency measurement of the down-hole sensor can be comparedto a surface measurement to determine if the stuck point is other thanthe drill bit. In some example embodiments, an accelerometer can be usedto detect variation in RPM.

In particular, stick slip is based on sensing tool rotation and onsensing tool rotation and variations in the rotary speed resulting frombinding in the BHA. This binding causes the tool to slow down as thetool binds and to speed up as the tool releases. The average rotaryspeed is consistent but the actual instantaneous RPM varies from nearlyzero to several times the average rotary speed. By measuring themagnitude of the RPM variation and its frequency, an indication of thestick slip condition can be provided to alert the surface operators thatmodification of the drilling operations is needed.

A magnetometer or similar device is used to measure the tool angularposition in the borehole. This angular position is referenced to somearbitrary zero position such as magnetic north or gravity high side.This angle will increase as the tool rotates in the borehole duringdrilling. FIG. 5 illustrates a graph of the angular change of the tool,according to some example embodiments. This graph illustrates asimulated angle measurement in a stick slip condition at an average of30 RPM. The horizontal axis is the sample number for an angle sampled ata 400 sample/second rate. The vertical axis is a measure of the totalangle, where the indicated integer value is the actual angle divided by1.5. The plot indicates that from sample 0 to 800, the angle changesfrom 75 to 315 for the angle (a change of 240 (360 degrees or 1revolution)). This is the correct total angular change for 2 seconds ofdata at 30 RPM. As seen, there is a sinusoidal appearance of the angleand this is the stick slip value to be measured. The slope of the plotis an indication of the average RPM (or angular speed) and the deviationfrom this straight line is the stick slip oscillation to be measured.

FIG. 6 is a plot of an angular measurement when the signal levels fromthe magnetometers are very low, according to some example embodiments.These signal levels can be low when the fields are very weak either dueto some shielding effect or sensor orientation relative to the fielddirection. The horizontal axis is time in seconds. This example includes5 seconds of data during which 2.5 revolutions occur. Note that theangle value cycles from 0 to 240 and back to 0 as 1 revolution iscompleted (and further note that the actual angle=the angle value*1.5).The plot illustrates the effect of noise, if an attempt were made tocalculate the RPM variation directly from this data. The noise effectswould be very significant, causing as much as 50% error in the readings.In general, a stick slip frequency will be less than 5 Hz and thepreferred sampling frequency is at least 10 Hz. However, due to the facethat there is underling noise in the measurement at frequenciesexceeding 100 Hz, the data can beneficially be sampled at a rate muchhigher than 10 Hz to allow contention with this noise signal. To reducethe noise effects, the data in one example is sampled at 400 Hz, thendigitally filtered with a linear phase Finite Impulse Response filter,and then digitally down-sampled to a rate adequate to describe the stickslip frequency.

FIGS. 7A-B show the characteristics of the down sampling filter,according to some example embodiments. The down sampling filter isapplied to the 400 Hz sampled data. A low pass with a 20 Hz cutofffrequency is then performed. The data is then linearly phased throughthe pass band (an important characteristic to assure proper descriptionof summed magnitudes for signals in the pass band). In other words, ifthe stick slip signal consisted of multiple frequencies, it can beimportant to maintain the relative phase between those frequencies toassure proper magnitude is indicated.

Returning to FIG. 6, another effect of noise is apparent. Some stickslip detection algorithms detect minimum and maximum RPM by measuringthe cycle time of the angle detector (e.g., the duration required forthe angle detector to cycle from 0 to 240 then cycle back to 0).However, when noise is introduced, this technique can be affected by thetoggling appearance of the angle reading at the transition point. Thisshortcoming of this algorithm is avoided by the RPM variance method,according to some example embodiments.

FIG. 8 illustrates a graph of the total angle calculated for a 20 seconddata window, according to some example embodiments. The vertical axis isangle in degrees, while the horizontal axis is sample number at a samplerate of 50 Hz. This data has been filtered then downsampled to a 50 Hzsample rate).

FIG. 9 illustrates a graph of the angular speed in RPM derived from FIG.8, according to some example embodiments by numerically taking the timederivative of the angular position in FIG. 8. The horizontal axis is thesame as for FIG. 8. The vertical axis is in units of RPM. The minimumrotary speed is 15 rpm, the maximum rotary speed is 49 RPM, while theaverage rotary speed is very close to 30 RPM Fourier techniques can beused to estimate the frequencies that are present, but in order tounderstand how these frequencies vary with time, frequency resolutionmust be compromised, often very seriously, to obtain temporalresolution.

In some example embodiments, especially where the signals are noisy,filtering can be avoided yet frequencies can be calculated to a highfrequency and temporal resolution if the data from two lateral,cross-axially arranged, magnetometers (data B_(x) and B_(y)) are used.The output of a properly calibrated pair of cross-axial magnetometerswith the same scale factor may be described byB _(x)(t)=A*sin(ω(t)*t+θ)B _(y)(t)=A*cos(ω(t)*t+θ)  Eq. 2in which ω is the angular frequency. Taking the derivative of bothcomponents, and then summing the squares of the derivatives:

$\begin{matrix}{\omega = \frac{\sqrt{\left( {\frac{\mathbb{d}}{\mathbb{d}t}{B_{x}(t)}} \right)^{2} + \left( {\frac{\mathbb{d}}{\mathbb{d}t}{B_{y}(t)}} \right)^{2}}}{\sqrt{{B_{x}(t)}^{2} + {B_{y}(t)}^{2}}}} & {{Eq}.\mspace{14mu} 3}\end{matrix}$

The derivatives can be taken numerically over short time intervals,allowing rapid frequency estimation. In addition, the denominator ofEquation 3 should be a very slowly varying function of time. Hence, afiltered version of this can be used in estimating ω.

To illustrate, FIG. 10 illustrates a distribution of frequencies,according to some example embodiments. The magnetometer was sampled at500 Hz. To obtain a satisfactory angular difference, points 10 samplesaway were used in calculating the derivative. For this particularsignal, the outputs had been normalized so that the amplitude was 1.Hence, there was no division by the amplitude. In addition, a verysimple filter was applied to the frequency estimates.

General

In the description, numerous specific details such as logicimplementations, opcodes, means to specify operands, resourcepartitioning/sharing/duplication implementations, types andinterrelationships of system components, and logicpartitioning/integration choices are set forth in order to provide amore thorough understanding of the present invention. It will beappreciated, however, by one skilled in the art that embodiments of theinvention may be practiced without such specific details. In otherinstances, control structures, gate level circuits and full softwareinstruction sequences have not been shown in detail in order not toobscure the embodiments of the invention. Those of ordinary skill in theart, with the included descriptions will be able to implementappropriate functionality without undue experimentation.

References in the specification to “one embodiment”, “an embodiment,” anexample embodiment,” etc., indicate that the embodiment described mayinclude a particular feature, structure, or characteristic, but everyembodiment may not necessarily include the particular feature,structure, or characteristic. Moreover, such phrases are not necessarilyreferring to the same embodiment. Further, when a particular feature,structure, or characteristic is described in connection with anembodiment, it is submitted that it is within the knowledge of oneskilled in the art to affect such feature, structure, or characteristicin connection with other embodiments whether or not explicitlydescribed.

Some or all of the operations described herein may be performed byhardware, firmware, software or a combination thereof. Upon reading andcomprehending the content of this disclosure, one of ordinary skill inthe art will understand the manner in which a software program can belaunched from a machine-readable medium in a computer-based system toexecute the functions defined in the software program. One of ordinaryskill in the art will further understand the various programminglanguages that may be employed to create one or more software programsdesigned to implement and perform the methods disclosed herein. Theprograms may be structured in an object-orientated format using anobject-oriented language such as Java or C++. Alternatively the programscan be structured in a procedure-orientated format using a procedurallanguage, such as assembly or C. The software components may communicateusing any of a number of mechanisms well-known to those skilled in theart, such as application program interfaces or inter-processcommunication techniques, including remote procedure calls. Theteachings of various embodiments are not limited to any particularprogramming language or environment.

In view of the wide variety of permutations to the embodiments describedherein, this detailed description is intended to be illustrative only,and should not be taken as limiting the scope of the invention. What isclaimed as the invention, therefore, is all such modifications as maycome within the scope and spirit of the following claims and equivalentsthereto. Therefore, the specification and drawings are to be regarded inan illustrative rather than a restrictive sense.

What is claimed is:
 1. A system comprising: a drill string having adrill bit, the drill string configured to extend through at least partof a well bore; a first vibrational sensor positioned on the drill bitto measure, at a first location on the drill string, one or more of anaxial vibration and a lateral vibration; a second vibrational sensorpositioned above the drill bit and on the drill string, the secondvibrational sensor to measure, at a second location on the drill string,one or more of an axial vibration and a lateral vibration; and aprocessor unit configured to determine a type of vibration based on acomparison of the measured vibration at the first location to themeasured vibration at the second location, and wherein the comparisoncomprises comparing the frequencies of the measured vibrations.
 2. Thesystem of claim 1, wherein the processor unit is positioned downhole inthe drill string, wherein the processor unit is to cause a signalindicative of the determined type of vibration to be transmitted to asurface location.
 3. The system of claim 2, wherein the drill string isused in a drilling operation to drill the wellbore, wherein a controlunit is to modify the drilling operation based on the determined type ofvibration.
 4. The system of claim 3, wherein the control unit is toalter rotations per minute of the drill string during the drillingoperation.
 5. The system of claim 1, wherein the determined type ofvibrations comprises bit whirl and bottom hole assembly (BHA) whirl. 6.The system of claim 1, wherein the second vibrational sensor ispositioned on a bottom hole assembly in the drill string.
 7. The systemof claim 1, wherein the first vibrational sensor or the second vibrationsensor comprises an accelerometer.
 8. The system of claim 1, furthercomprising a third vibrational sensor positioned above the secondvibrational sensor to measure, at a third location on the drill string,one or more of an axial vibration, a torsional vibration and a lateralvibration.
 9. The system of claim 1, wherein the compared frequencies ofthe first and second measurements, comprise a plurality of vibrationmeasurements from each location.
 10. An apparatus comprising: a firstmulti-axial transducer, located at a drill bit on a drill string, tomonitor an amplitude of at least an axial vibration and a lateralvibration at a first location; a second multi-axial transducer, locateda spaced distance above the drill bit, to monitor an amplitude of atleast an axial vibration and a lateral vibration at a second location;and a processor unit to evaluate the two amplitudes, wherein theprocessor unit is to detect at least one vibration mechanism based onthe evaluation of the amplitudes.
 11. The apparatus of claim 10, whereinthe first multi-axial transducer comprises a first tri-axial transducerand the second multi-axial transducer comprises a second tri-axialtransducer.
 12. The apparatus of claim 11, wherein the first tri-axialtransducer is to monitor the amplitude of the axial vibration, and theamplitude of the lateral vibration at the first location and wherein thesecond tri-axial transducer is to monitor the amplitude of the axialvibration and the amplitude of the lateral vibration at the secondlocation.
 13. The apparatus of claim 12, wherein the processor unit isto determine which of the amplitudes is greater for each of the axialvibration and the lateral vibration.
 14. The apparatus of claim 13,wherein the processing unit is to alter a weight on the drill bit duringthe drilling operation.
 15. The apparatus of claim 10, furthercomprising a telemetry device, wherein the processor unit is to causethe telemetry device to transmit a signal from downhole to the surfacethat indicates that the at least one vibration mechanism is bit whirl ifthe amplitude at the first location is at least N percentage greaterthan the amplitude at the second location.
 16. The apparatus of claim10, wherein the drill string is used in a drilling operation to drillthe well bore, wherein a control unit is to modify the drillingoperation based on the at least one vibration mechanism.
 17. A methodcomprising: receiving measurement of at least one of an axial vibrationand a lateral vibration from a first transducer positioned at a firstlocation on a drill string near a drill bit thereof; receivingmeasurement of at least one of an axial vibration and a lateralvibration from a second transducer positioned at a second location onthe drill string a spaced distance above the drill bit; comparing themeasurement for the first location to the measurement for the secondlocation, and further comparing at least one of said measurements to areference; and detecting a vibration mechanism on the drill string basedon the comparing.
 18. The method of claim 17, detecting the vibrationmechanism on the drill string comprises detecting bit bounce if a peakacceleration for both measurements for axial vibration is about 40 g orgreater.